Attenuated total internal reflection optical sensor for obtaining downhole fluid properties

ABSTRACT

A downhole fluid analysis system includes an optical sensor comprising, which includes a light source configured to emit light comprising a plurality of wavelengths, a light detector, and an optical tip through which at least a portion of the light travels and returns to the detector, wherein the incident angle of the light causes total internal reflection within the optical tip. The system further includes a piezoelectric helm resonator that generates a resonance response in response to an applied current, and an electromagnetic spectroscopy sensor positioned symmetrically with respect to the piezoelectric helm resonator in at least one direction. The light may be reflected in the optical tip at one or more reflection points, and each reflection point may generate an evanescent wave in a medium surrounding the optical tip. The light may be internally reflected in the optical tip at a plurality of reflection points.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Patent Application No.62/846,548 filed May 10, 2019 titled “SYSTEMS AND METHODS FOR OBTAININGDOWNHOLE FLUID PROPERTIES,” the disclosure of which is incorporatedherein by reference in its entirety.

BACKGROUND 1. Field of the Invention

The present disclosure relates to downhole measurements. Moreparticularly, the present disclosure relates to obtaining a number ofproperties of the fluid inside a wellbore.

2. Description of Related Art

During oil and gas operations, it is often difficult to determine fluidproperties in a downhole well due to inaccessibility, contamination offluids, mixing of fluids, and the like. As a result, typical operationsdeploy multiple tools that may be specialized to determine a singlefluid property, such as density. These tools are often fragile, and as aresult, may not be utilized in multiple operations. Furthermore,installing multiple tools along a drill or wireline string increasescosts of the operation and also may lead to slower drilling and orwireline logging operations because some tools are individually trippedinto and out of the well. In additional, current techniques areincapable of performing true multi-phase fluid metering. Absorption ortransmission spectroscopy is a commonly used optical analysis technique.The change in transmitted intensity can be measured through a variety ofoptical techniques. Constituents of a sample absorb light of respectivewavelengths/frequencies. The amount of light absorbed by the sample atdifferent wavelengths/frequencies depends on the presence andconcentration of each constituent. Therefore, the absorption spectrum ofthe sample, or the frequency distribution of the absorbed light, can beused to identify the composition of the sample. Transmission absorptionspectroscopy requires samples that are substantially opticallytranslucent or transparent in the range of frequencies being studied.Therefore, conventional absorption spectroscopy may be difficult foranalyzing dark or opaque samples or for highly scattering fluids thatcontain suspended particles such as sand or which contain small bubblesof one immiscible phase within another such as emulsions.

SUMMARY

Applicants recognized the problems noted above herein and conceived anddeveloped embodiments of systems and methods, according to the presentdisclosure, for a multi-modal sensing and identification of fluidproperties. By measuring multiple properties, applicants can distinguishall three phases, gas, liquid, and oil rather than just distinguishingliquid versus gas as is presently done.

In an embodiment, a downhole fluid analysis system includes an opticalsensor comprising, which includes a light source configured to emitlight comprising a plurality of wavelengths, a light detector, and anoptical tip through which at least a portion of the light travels andreturns to the detector, wherein the incident angle of the light causestotal internal reflection within the optical tip. The system furtherincludes a piezoelectric helm resonator that generates a resonanceresponse in response to an applied current, and an electromagneticspectroscopy sensor positioned symmetrically with respect to thepiezoelectric helm resonator in at least one direction. The light may bereflected in the optical tip at one or more reflection points, and eachreflection point may generate an evanescent wave in a medium surroundingthe optical tip. The light may be internally reflected in the opticaltip at a plurality of reflection points. The light may cause florescencein a medium surrounding the optical tip, which indicatives the presenceof oil in the medium. The light emitted by the light source includes atleast a first wavelength and a second wavelength. Attenuation of thefirst wavelength indicates presence of a first fluid type adjacent theoptical tip and attenuation of the second wavelength indicates presenceof a second fluid type adjacent the optical tip. The first wavelength isattenuated by the presence of oil and the second wavelength isattenuated by the presence of water. The light detector may be aspectrally resolved detector and detects intensity of differentwavelength in the received light. The optical sensor may be positionedsymmetrically with respect to the piezoelectric helm resonator.

In another embodiment, a downhole fluid analysis device includes anoptical sensor which includes a first light source that emits light of afirst wavelength, a second light source that emits light of a secondwavelength, a beam combiner positioned to combine the light from thefirst light source and light from the second light source into a lightbeam, an optical tip positioned to receive the light beam, in which anangle of incidence of the light beam creates internal reflection of thelight beam within the optical tip, and a light detection systempositioned to receive returned light from the optical tip, the lightdetector resolving wavelengths present the returned light, and theintensity of the wavelengths. The first light source may emit a visiblelight and the second light source may emit an infrared light, and thelight beam includes the visible light and the infrared light. The lightdetection system may include a visible light detector and an infraredlight detector. The light detection system may include a spectrallyresolved light detector. The light is reflected in the optical tip atone or more reflection points, and each reflection point generates anevanescent wave in a medium surrounding the optical tip. The light beamis internally reflected in the optical tip at a plurality of reflectionpoints. The light detection system may detect attenuation of the firstwavelength and the second wavelengths based on the returned light, inwhich attenuation of the first wavelength indicates presence of a firstfluid type adjacent the optical tip and attenuation of the secondwavelength indicates presence of a second fluid type adjacent theoptical tip. Specifically, attenuation of the first wavelength may beattenuated by the presence of oil and attenuation of the secondwavelength may be attenuated by the presence of water.

In another embodiment, a method of obtaining fluid properties in a wellincludes positioning a fluid sensor in a wellbore, in which the fluidsensor includes co-located piezoelectric helm resonator, optical sensor,and electromagnetic spectroscopy sensor. The method further includesapplying electrical energy to the piezoelectric helm resonator to excitethe piezoelectric helm resonator, receiving a signal from thepiezoelectric helm resonator, determining one or more of density,viscosity, or sound speed of a region of fluid in the wellbore based atleast in part the first signal from the piezoelectric helm resonator,and receiving an electromagnetic spectroscopy signal from thespectroscopy sensor. The method also includes emitting a light into anoptical tip of the optical sensor, directing the light through aplurality of internal reflections in the optical tip before exiting theoptical tip as returned light, receiving the returned light from theoptical tip at a light detection system, and analyzing the spectralcontent of the returned light to determine components of the fluid. Thelight may be reflected in the optical tip at one or more reflectionpoints, and wherein each reflection point generates an evanescent wavein a medium surrounding the optical tip. The method may also includedetermining a concentration of oil in the fluid based on the intensityof the first wavelength in the returned light, and determining aconcentration of water in the fluid based on the intensity of the secondwavelength in the returned light.

BRIEF DESCRIPTION OF DRAWINGS

The foregoing aspects, features, and advantages of the presentdisclosure will be further appreciated when considered with reference tothe following description of embodiments and accompanying drawings. Indescribing the embodiments of the disclosure illustrated in the appendeddrawings, specific terminology will be used for the sake of clarity.However, the disclosure is not intended to be limited to the specificterms used, and it is to be understood that each specific term includesequivalents that operate in a similar manner to accomplish a similarpurpose.

FIG. 1 is a schematic side view of an embodiment of a wireline system,in accordance with embodiments of the present disclosure.

FIG. 2 illustrates a perspective view of a fluid analysis tool in anexpanded position, in accordance with example embodiments.

FIG. 3A illustrates the fluid analysis tool in the retracted position,in accordance with example embodiments.

FIG. 3B illustrates the fluid analysis tool in a first expandedposition, in accordance with example embodiments.

FIG. 3C illustrates the fluid analysis tool in a second expandedposition, in accordance with example embodiments.

FIG. 4 is a graph illustrating the deployment angles of the arms, thefluid sensors, and the flow spinners with respect to the casing innerdiameter, in accordance with example embodiments.

FIG. 5 illustrates a perspective view of a downhole fluid analysisdevice, in accordance with example embodiments.

FIG. 6 illustrates a perspective view of the piezoelectric helmresonator of the downhole fluid analysis device, in accordance withexample embodiments.

FIG. 7 illustrates an example circuit that can be used with embodimentsof the present disclosure.

FIG. 8 illustrates a cross-sectional diagram view of the sensor of FIG.5, in accordance with example embodiments.

FIG. 9 illustrates an example waveform associated with operation of thecircuit of FIG. 7, in accordance with example embodiments.

FIG. 10 illustrates another example embodiment of a circuit that can beused with embodiments of the present disclosure.

FIG. 11 illustrates a waveform for operation of the circuit of FIG. 10,in accordance with example embodiments.

FIG. 12 illustrates light of multiple wavelengths traveling from a lightsource, through an optical tip, and to a detector, in accordance withexample embodiments of the present disclosure.

FIG. 13 illustrates the reflection and attenuation of light through atip of an optical sensor, in accordance with example embodiments of thepresent disclosure.

FIG. 14 illustrates an optical sensor with a bi-conical shape, inaccordance with example embodiments of the present disclosure.

FIG. 15 is a diagram illustrating a bi-conical tip for an opticalsensor, in accordance with example embodiments of the presentdisclosure.

FIG. 16 illustrates a plurality of example configurations of bi-conicaloptical tips, in accordance with example embodiments.

FIG. 17 is a system diagram illustrating an optical sensor, inaccordance with example embodiments of the present disclosure.

FIG. 18 is a flow chart of an embodiment of a method for collecting andanalyzing data utilizing the downhole fluid analysis device, inaccordance with example embodiments.

FIG. 19 is a block diagram of an embodiment of a machine learning systemthat may be utilized with embodiment of the present disclosure, inaccordance with example embodiments.

DETAILED DESCRIPTION

The foregoing aspects, features, and advantages of the presentdisclosure will be further appreciated when considered with reference tothe following description of embodiments and accompanying drawings. Indescribing the embodiments of the disclosure illustrated in the appendeddrawings, specific terminology will be used for the sake of clarity.However, the disclosure is not intended to be limited to the specificterms used, and it is to be understood that each specific term includesequivalents that operate in a similar manner to accomplish a similarpurpose.

When introducing elements of various embodiments of the presentdisclosure, the articles “a”, “an”, “the”, and “said” are intended tomean that there are one or more of the elements. The terms “comprising”,“including”, and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements. Anyexamples of operating parameters and/or environmental conditions are notexclusive of other parameters/conditions of the disclosed embodiments.Additionally, it should be understood that references to “oneembodiment”, “an embodiment”, “certain embodiments”, or “otherembodiments” of the present disclosure are not intended to beinterpreted as excluding the existence of additional embodiments thatalso incorporate the recited features. Furthermore, reference to termssuch as “above”, “below”, “upper”, “lower”, “side”, “front”, “back”, orother terms regarding orientation or direction are made with referenceto the illustrated embodiments and are not intended to be limiting orexclude other orientations or directions.

Embodiments of the present disclosure provide a piezoelectric helmresonator sensor array having simultaneous and mathematically congruentfluid density, viscosity, and sound speed measurements as well asintegrated electromagnetic and optical spectroscopy characterization.Acoustic measurements are important in determining composition andchemical properties of unknown multi-phase fluids for applications in avariety of fields. Current devices and methods, such as those formeasuring either fluid density or fluid sound speed rely on an a prioriknowledge of the mass density of the continuous and dispersed phases ofthe flow, and are primarily for surface separation systems. However,existing approaches are not applicable to in situ downhole applicationssince the mass densities of the components of the flow are not generallyknown and are only estimable from surface “dead oil” properties that donot account for effects such as downhole pressure, temperature, andgas-saturation. Fluid optical properties and characteristics can bederived downhole from some of the following optical measurementtechniques: reflectance, emittance, transmittance, absorbance,fluorescence, optical spectroscopy, refractive index dependent opticalmeasurements, and others techniques known in the optical instrumentationart.

Embodiments of the present disclosure provide techniques (e.g., devices,systems, tools, methods) that allow multi-phase fluid properties (e.g.,volume fractions, gas-oil-ratio, live-oil density, live-oil sound speed,and live-oil compressibility) to be determined from the directionmeasureable composite fluid acoustic properties of sound speed, bulkmodulus and acoustic impedance. In order to make these correlations themeasurements for sound speed, acoustic impedance and bulk modulus of thecomposite fluid flow must be obtained in a specific congruent manner.That is, from a single measurement domain [M-domain] with a sensingfield of interaction that is simultaneous and congruent relative to allthe acoustic measurements and all the continuous/dispersed particles.

Many factors present difficulty to the development of sensortechnologies capable of these types of acoustic compositionalmeasurements. Most important of these is the necessity for simultaneousand congruent measurements with respect to each other, thus providing atrue measure of the bulk composite fluid density and sound speed thathave correlations with compositional and chemical properties of the bulkfluid from the same volumetric sample within the sample zone measured.Existing approaches utilize two separate measurements of twonon-identical fluid domains, for example M1-domain and M2-domain, toobtain measurements for fluid sound speed c1 in M1-domain and fluid massdensity p2 in M2-domain. By measuring mass density and sound speed onecan compute bulk modulus (inverse compressibility) because it equals theproduct of the fluid's mass density with the square of its sound speed.High compressibility is an indicator of high gas-oil ratio.

In order to examine the correlations that may exist between the variouscompositional properties of liquid-liquid flows and the bulk fluidacoustic properties of the mixtures, an ideal acoustic impedance sensorthat can measure simultaneously and congruently fluid density and soundspeed properties is needed. Further, it is tacitly required that thesensor measurement attained provide delineated bulk fluid propertiesestimates of mass density and sound speed that can be discriminateddirectly from the measurement without any a priori knowledge of orassumption with regard to elemental properties of the bulk compositefluid. Embodiments of the present disclosure provide a piezoelectrichelm resonator sensor array having simultaneous and mathematicallycongruent fluid density, viscosity, and sound speed measurements as wellas integrated electromagnetic and optical spectroscopy characterization.

FIG. 1 is a schematic elevation view of an embodiment of a wellboresystem 10 that includes a work string 12 shown conveyed in a wellbore 14formed in a formation 16 from a surface location 18 to a depth 20. Thewellbore 14 is shown lined with a casing 22, however it should beappreciated that in other embodiments the wellbore 14 may not be cased.In various embodiments, the work string 12 includes a conveying member24, such as an electric wireline, and a downhole tool or assembly 26(also referred to as the bottomhole assembly or “BHA”) attached to thebottom end of the wireline. The illustrated downhole assembly 26includes various tools, sensors, measurement devices, communicationdevices, and the like, which will not all be described for clarity. Invarious embodiments, the downhole assembly 26 includes a measurementmodule 28, which will be described below, determining one or moreproperties of the formation 16. In the illustrated embodiment, thedownhole tool 28 is arranged in a horizontal or deviated portion 30 ofthe wellbore 14; however it should be appreciated that the downhole tool28 may also be deployed in substantially vertical segments of thewellbore 14.

The illustrated embodiment further includes a fluid pumping system 32 atthe surface 18 that includes a motor that drives a pump to pump a fluidfrom a source into the wellbore 14 via a supply line or conduit. Tocontrol the rate of travel of the downhole assembly, tension on thewireline 14 is controlled at a winch on the surface. Thus, thecombination of the fluid flow rate and the tension on the wireline maycontribute to the travel rate or rate of penetration of the downholeassembly 16 into the wellbore 14. The wireline 14 may be an armoredcable that includes conductors for supplying electrical energy (power)to downhole devices and communication links for providing two-waycommunication between the downhole tool and surface devices. In aspects,a controller 34 at the surface is provided to control the operation ofthe pump and the winch to control the fluid flow rate into the wellboreand the tension on the wireline 12. In aspects, the controller 34 may bea computer-based system that may include a processor 36, such as amicroprocessor, a storage device 38, such as a memory device, andprograms and instructions, accessible to the processor for executing theinstructions utilizing the data stored in the memory 38.

As described above, the illustrated embodiment includes the measurementmodule 28. As will be described below, in various embodiments, themeasurement module 28 may include one or more piezoelectric helmresonators for determination of various fluid properties within thewellbore 14. For example, oil and gas products may enter an annulus andflow along the BHA 26. At least a portion of that flow may be redirectedinto the measurement module 28. Within the measurement module 28, orproximate the measurement module 28 in certain embodiments, one or morefluid properties may be measured to facilitate wellbore operations.Furthermore, it should be appreciated that while various embodimentsinclude the measurement module 28 incorporated into a wireline system,in other embodiments the measurement module 28 may be associated withrigid drill pipe, coiled tubing, or any other downhole exploration andproduction method.

In some embodiments, the measurement module 28 includes a fluid analysistool. FIG. 2 illustrates a perspective view of a fluid analysis tool 40in an expanded position, in accordance with example embodiments. Asillustrated, in some embodiments, the fluid analysis tool 40 includes aplurality of arms 42 movable from a retracted position into an expandedposition. In some embodiments, the plurality of arms 42 are fixed atopposing ends 44, 46 and bendable at least one location (e.g., pivot)between the opposing ends 44, 46. The plurality of arms 42 are arrangedabout a central axis 48 of the system, such that the plurality of arms42 expand away from the central axis 48 to move into the expandedposition and contract towards the central axis 48 to position into theretracted position. In some embodiments, the tool may include a centralbody 50 substantially align with the central axis 48. The central body50 may be configured to receive or store the plurality of arms 42 in theretracted position. In some embodiments, the central body 50 may includerecessed portions 56 for receiving the arms and may include additionallyrecessed portions 58 for receiving the fluid sensors and/or flowspinners on the arms.

In some embodiments, each of the plurality of arms 42 includes one ormore fluid sensors 52 coupled thereto. At least one of the fluid sensors52 includes a piezoelectric helm resonator, an optical sensor, and aspectroscopy sensor. As will be discussed in further detail below, thepiezoelectric helm resonator includes a strain bar comprising a firstside, a second side opposite the first side, a first end, and a secondend opposite the first end. The piezoelectric helm resonator furtherincludes a pair of electrodes, in which a first electrode of the pair ofelectrodes is positioned on the first side and a second electrode of thepair of electrodes is positioned on the second side. The piezoelectrichelm resonator further includes a pair of tines, in which a first tineof the pair of tines is coupled to the first end and a second tine ofthe pair of tines is coupled to the second end, the pair of tines eachhaving an arc, and such that strain across a transverse face of thestrain bar generates a resonance response from the pair of tines. Theoptical sensor is positioned centrally with respect to the piezoelectrichelm resonator, and the spectroscopy sensor is positioned symmetricallywith respect to the piezoelectric helm resonator in at least ondirection.

There may be a plurality of fluid sensors 52 on each arm, as illustratedin FIG. 2, and thus a plurality of fluid sensors 52 on the tool 40,which could be used for production logging. The plurality of fluidsensors 52 may be the same type of device or multiple types of devices.The fluid sensors 52 are individually addressable, such that the dataobtained from each fluid sensor 52 can be associated with the respectivesensor. Since each fluid sensor 52 is in a different position and thusdifferent location in the wellbore, the data from each fluid sensor 52can be associated with a specific location in the wellbore.

The fluid sensors 52 may be coupled to the respective arm 42 via a pivotand configured to swing inwardly away from the respective arm 42 towardsa central axis 48 or central body 50 of the tool 40. Alternatively, insome embodiments, the fluid sensors 52 may be configured to swingoutward away from the respective arm 42 and away from the central body50 or to the side in a direction tangential to a central axis 48 of thetool 40. The fluid sensors 52 may be movable from a stored position to adeployed position relative to the respective arm 42 on which a fluidsensor 52 is located. In the stored position, the fluid sensors 52 maybe stored in the arms 42. In the deployed position, the fluid sensors 52are extended out from the arms 42 and positioned substantially parallelto the axis of the borehole. In some embodiments, the fluid sensors 52are at an angle within certain degrees from an axis of a borehole inwhich the system is positioned. Thus, the fluid sensors 52 arepositioned to substantially face the direction of fluid flow through theborehole. In some embodiments, at least one of the plurality of arms 42comprises a flow spinner 54 located thereon to direct the fluid flow foralignment with the fluid sensors 52.

In the illustrated example embodiments, the tool includes six arms 42,with two fluid sensors 52 and two spinners 54 integrated into each arm42. The sensors 52 and spinners 54 may each be articulated with afour-bar mechanism that compensates for the deployment angle of thearray arms 42 to maintain the sensors 52 and spinners 54 to within ±5degrees orientation to the borehole axis regardless of the arm'sdeployment angle, as illustrated below with respect to FIGS. 3A, 3B, and3C. The four-bar mechanisms may also nest the sensor\spinner array inthe tool chassis pockets upon array retraction. Other pivoting orpositioning mechanism may be employed to achieve the same or similarmovement dynamics.

FIG. 3A illustrates the fluid analysis tool in the retracted position60, in accordance with example embodiments. As mentioned, in someembodiments, the plurality of arms 42 are arranged about a central body50 (FIG. 2) of the tool 40. The central body 50 may be configured toreceive or store the plurality of arms 42 in the retracted position.Each of the arms 42 may be the same length as the receiving portion ofthe central body 50 such that each arm 42 may be substantially flushagainst the central body 50, creating the minimum circumference of thetool 40. The fluid analysis tool may be lowered downhole in thecontracted position and then deployed into an expanded position.

FIG. 3B illustrates the fluid analysis tool 40 in a first expandedposition 62, in accordance with example embodiments. For example, thisposition may be used for deployment in a 5″ casing. As illustrated, inthe first expanded position 62, each of the arms 42 bends outward,putting the arms 42 at an angle with respect to the central body 50. Thefluid sensors 52 and flow spinners 54 are also deployed out from thearms 42 at an angle from the respective arm 42. FIG. 3C illustrates thefluid analysis tool in a second expanded position 64, in which the arms42 expand further outward than in the first expanded position 62. Forexample, this position may be used for deployment in a 10″ casing.Similar to the first expanded position 62, in the second expandedposition 64, each of the arms 42 bends outward at an angle and the fluidsensors 52 and flow spinners 54 are deployed out from the arms 42. Inthe second expanded position 64, the arms 42 are at a larger angle fromthe central body 50. However, the fluid sensors 52 and flow spinners 54also deploy at a larger angle from the arms 42, compensating for thelarger angle between the arms 42 and the central body 50. Thus, thefluid sensors 52 and flow spinners 54 are maintained at a minimal anglefrom the central body 50 or central axis 48 of the tool 40. Asmentioned, the tool 40 may be designed to maintain the fluid sensors 52and flow spinners 54 within ±5 degrees orientation to the borehole axis.

FIG. 4 is a graph 70 illustrating the deployment angles 72 of the arms76, the fluid sensors 78, and the flow spinners 80 with respect to thecasing inner diameter 74. As illustrated, the deployment angle of thearms 76 increases as the casing inner diameter 74 increases, as the armsexpand further outward for larger boreholes. However, as the deploymentangle of the arms 76 gets larger (i.e., tool expands further outward),the angles of the fluid sensors 78 and flow spinners 80 do not continueto increase accordingly. Rather, it stays within ±5 degrees regardlessof the angle of the arms 76. Various embodiments and implementations ofthe tool may allow for different ranges. For example, some embodimentsmay be rated for ±2 degrees, ±10 degrees, etc.

FIG. 5 illustrates a perspective view of a downhole fluid analysisdevice 90, such as the fluid sensors in the fluid analysis tool of FIG.2, in accordance with example embodiments. The downhole fluid analysisdevice 90 includes a piezoelectric helm resonator 92, an optical sensor94, and a spectroscopy sensor 96. The piezoelectric helm resonator 92includes a strain bar 98 comprising a first side 100, a second side (notin view) opposite the first side 100, a first end 102 and a second end104 opposite the first end 102. The piezoelectric helm resonator 92further includes a pair of tines 106, 108, in which a first tine 106 ofthe pair of tines is coupled to the first end 102 and a second tine 108of the pair of tines is coupled to the second end 104. In someembodiments, the tines 106, 108 each have an arc, such that strainacross a transverse face of the strain bar 98 generates a resonanceresponse from the tines 106, 108. It should be appreciated, and will bedescribed further below, that the strain bar 154 may also be referred toas a Poisson strain bar and, moreover, may not have a uniform thicknessacross its length. That is, various portions of the straight bar 154 maybe adjusted or otherwise formed in order to reduce weight, induce acertain resonance frequency, create and/or eliminate certain sensitivityto fluid properties, and the like.

The piezoelectric helm resonator 92 further includes a pair ofelectrodes located thereon, in which a first electrode 110 of the pairof electrodes is positioned on the first side 100 and a second electrode(not in view) of the pair of electrodes is positioned on the secondside. In some embodiments, the pair of electrodes is coupled to anelectric circuit comprising a signal coupling or tuning device. Thepiezoelectric helm resonator receives electrical energy from theelectrodes 110. In various embodiments, the electrical energytransmitted from the electrodes 110 induces a vibration within thepiezoelectric helm resonator 92, for example due to resonantdisplacement as a result of electrodes 110 arranged on the piezoelectrichelm resonator 92. This vibration may be utilized to measure one or moreproperties of fluid surrounding and/or flowing along the piezoelectrichelm resonator 92.

In the illustrated embodiment, the piezoelectric helm resonator 92design is based on the combination of a Poisson strain bar 98 and asymmetric pair of vibratory helm-geometry tines 106, 108. The helm tines106, 108 are excited by placing an electrical voltage across opposingfaces of the transverse thickness of the piezoelectric strain bar 98segment to develop an oscillatory contraction/expansion of the barthickness. Due to the Poisson's ratio effect, this through-thicknessoscillatory motion develops a longitudinal oscillatory displacementalong the length of the bar 92 that excites the helm tines 106, 108 intoresonance response. Due to the helm geometry of the tines 106, 108, thefrequency and bandwidth of the resonance response is dependent upon thevisco-acoustic properties of the fluid surrounding the tines 106, 108.This characteristic can be used to determine the visco-acousticproperties of the fluid, namely fluid density, viscosity, and soundspeed, from measurement of the electrical admittance spectrum (50-60kHz) on the piezoelectric resonator driving circuit.

The optical sensor 94 is positioned centrally with respect to thepiezoelectric helm resonator 92, and the spectroscopy sensor 96 ispositioned symmetrically with respect to the piezoelectric helmresonator 92 in at least one direction.

In some embodiments, the fluid analysis device 90 also includes a flowmeter comprising a resistance thermometer detector. In some embodiments,such as in the illustrated embodiment, the spectroscopy sensor may be anelectromagnetic spectroscopy sensor, in which the electromagneticspectroscopy sensor comprises at least one electromagnetic spectroscopycoil 116 located on at least one of the pair of electrodes 110. In theillustrated embodiment, there are four coils 116 in total, with twocoils 116 located on each electrode. Thus, there are two coils 116 onthe first 100 side of the piezoelectric helm resonator 92 and two coilson the second side of the piezoelectric helm resonator 92. These coils116 may develop an electromagnetic dipole field in the fluid in order toobtain an electromagnetic impedance spectroscopy for the fluid.

In some embodiments, the device 90 may include a dielectric spectroscopysensor, in which the dielectric spectroscopy sensor includes electrodesspaced apart to allow fluid to fill a space between the electrodes.Thus, the fluid can be analyzed using dielectric spectroscopytechniques. In certain such embodiments, the spectroscopy sensor canutilizes the pair of electrodes on the piezoelectric helm resonator. Forexample, the pair of electrodes on the piezoelectric helm resonator mayeach include a portion extending into the fluid such that a portion offluid is between the electrodes. As would be understood, in variousembodiments the dielectric constants of water, rock, and oil may be usedto estimate water content in a downhole formation. In variousembodiments, this information may be utilized to determine theconductivity of the fluid sample. Furthermore, the conductivity mayfurther be used, at least in part with a machine learning method, inorder to provide a quantitative assessment of contamination, as will bedescribed further below.

Dielectric assessment of materials including fluids has been shown as aneffective method for electromagnetic characterization of a broad rangeof materials, fluids, chemical products, fluid mixes, and composites.The interaction of a material with an applied electric field can beevaluated with dielectric spectroscopy techniques. The complex relativepermittivity of liquids and gases depends on the dielectric constant,loss factors, chemical composition, material physical structure,frequency and temperature. Complex dielectric permittivity includes areal component and an imaginary component. The real component of thecomplex dielectric permittivity is the dielectric constant and theimaginary component is the loss factor component.

Various instruments can measure complex dielectric permittivity withvarying range of measurement capabilities such as impedance analyzers,scalar network analyzers, vector network analyzers (VNA), Time-DomainReflectometry meter (TDR), and Frequency-Domain Reflectometry meter(FDR). Different instrumentation probes types are available for eitherreflection or transmission based measurements. For example a FourierTransform obtained from a reflectogram of the sensor responding to anexcitation pulse can provide the frequency spectrum of complexdielectric permittivity. Over the frequency range of electromagneticspectroscopy, various physical dielectric response mechanisms of fluidmaterials are measured under the effect of electromagnetic fields foreach frequency region. From low frequency to higher frequencies, thefollowing fluid flow physical polarization mechanisms are activated andsensed by the electromagnetic spectroscopy probes: ionic conductivity(10³ to 10⁹ Hz), dipolar (10⁷ to 10⁹ Hz), atomic level (10⁹ to 10¹⁴ Hz),electronic (10¹⁴ to 10¹⁶ Hz).

The electromagnetic spectroscopy, including the electromagneticdielectric spectroscopy of the present disclosure, includes the fluidmaterials' complex relative permittivity spectrum over the frequencyrange of interest. The electromagnetic dielectric spectroscopy can beperformed over a dipolar frequency range, including the helm resonatorresonating frequency range with the helm resonators' electrode probes.In some embodiments, electromagnetic dielectric spectroscopy can beperformed at lower frequency range up to the frequency region of thehelm resonating frequency region with an added circuit, such as thecircuit illustrated in FIG. 7, which senses fluid capacitance C_(f),which is associated with the flowing fluid dielectric permittivity. Atvery low frequencies the parallel complex impedance of the circuitillustrated in FIG. 7 will be dominated by the impedance of the RTD_(f)(real component) as C_(f) impedance will be very large in this lowfrequency range. RTD_(f) can be extracted under these low frequencymeasurement conditions. FIG. 5 also illustrates two capacitor plates120(C_(f)-A) and 122 (C_(f)-B) from a capacitor C_(f,) which are exposedto fluid. An RTD_(f) 124 is also exposed to fluid. In one embodiment,RTD_(f) could be electrically isolated from the fluid by a thinthermally conductive layer applied to the sensing sensor surface exposedto the fluid.

As the measurement frequency is increased within the low frequencyrange, the complex impedance may show measurements sensitive to bothRTD_(f) and C_(f). The complex impedance of C_(f) may show sensitivityto fluid flow dielectric permittivity and also to the fluid ionic ohmicloss (heat), both of which could be resolved with multiple frequencymeasurements given RTD_(f) was resolved in the very low frequency end ofthe measurement spectrum. There are correlation dependencies between thecomplex dielectric properties described here and other chemical andphysical properties of the fluid flow with multiple phase components,including emulsions, surfactants, production injection additives and avariety of flow contaminants. The chemical and physical properties couldinclude at least density, viscosity, and sonic speed. The respectivecorrelations between such properties and the complex dielectricspectroscopy data could be processed and applied with a machine learningsystem to provide automated or semi-automated production fluid flowinterpretation, diagnostics, analysis, and reservoir productiondevelopment and flow assurance management decision making.

In some embodiments, the fluid analysis device 90 further includes aconnection interface 118, such as a coaxial stab connection, forproviding power and/or communication connections. The connectioninterface 118 may include an electrical connection coupled to the pairof electrodes 110, an acoustic channel for the piezoelectric helmresonator 92, and an optical channel for the optical sensor 112. In someembodiments, the interface 118 may include a channel coupled to andshared by the piezoelectric helm resonator 92 and the spectroscopysensor 114, in which the channel carries an acoustic signal generated bythe piezoelectric helm resonator 92 and an electrical signal generatedby the spectroscopy sensor 114. The connection interface 118 may coupleto fluid analysis device 90 to a cable so that power can be delivered tothe fluid analysis device 90 and data can be transmitted from the fluidanalysis device 90 to a controller or control station. The cable may bea coaxial cable with concentric feedthrough. The coaxial cable mayinclude a center core fiber for carrying optical data. The cable mayinclude concentric coaxial conductor having cylindrical geometry orhelical geometry. The connection interface 118 may be configured to becompatible with various different types of cables.

FIG. 6 illustrates a perspective view of the piezoelectric helmresonator 92, in accordance with example embodiments. As mentioned, thepiezoelectric helm resonator 92 includes a strain bar 98 comprising afirst side 100, a second side (not in view) opposite the first side, afirst end 102, and a second end 104 opposite the first end 102. Invarious embodiments, a fillet 122 or other connection is positionedbetween the strain bar 98 and the tines 106, 108. As illustrated, thefillet 122 is curved, which reduces stresses between the strain bar 98and the tines 106, 108. The piezoelectric helm resonator 92 furtherincludes a pair of electrodes, in which a first electrode 110 of thepair of electrodes is positioned on the first side 100 and a secondelectrode (not in view) of the pair of electrodes is positioned on thesecond side opposite the first side 100. In some embodiments, an opticalport 120 or orifice is formed through the center of the strain bar 98such that the optical sensor 94 (FIG. 5) can extend there through or atleast provide a sensing window for the optical sensor 94.

FIG. 7 illustrates an example circuit 160 that can be used withembodiments of the present disclosure. The circuit 160 includes someelectric circuit components, including diodes D1 166 and D2 168, whichmay be embedded in the multi-sensor assembly 90 of FIG. 5 in order forthe several sensor measurements to be performed over two wires. Asillustrated, the resonator 170 is connected in parallel with the RTD_(f)172 and capacitor C_(f) 174. Other electrical circuit embodiments toenable multiple sensor measurements over two wires could involveMOSFET's switching, relay, selective frequency dependence circuits,Zener diode, etc. These two wires are routed to the deployment arm mountin the tool assembly 40 of FIG. 2, connecting to circuit terminals T1162 and T2 164 via a pressure bulkhead feed through. FIG. 8 illustratesa cross-sectional diagram view 180 of the sensor of FIG. 5, inaccordance with example embodiments. As illustrates, the RTD_(f) 182 andcapacitor plates 184, 186 are located on the sensor and exposed to thefluid. Wires 192, 194 extend into the sensor, coupling to the RTD_(f)182 and capacitor plates 184, 186, as well as the resonator 188. Thewires 192, 194, along with the optical channel 190, extend out of thesensor, forming a connection interface.

FIG. 9 illustrates an example waveform 200 associated with operation ofthe circuit of FIG. 7. When the voltage terminal T1 with respect toterminal voltage T2 is negative, diode D1 is OFF and diode D2 is ON. Inthis diode ON-OFF bias condition, the measurements across terminals T1and T2 of complex impedance of respective fluid sensors RTD_(f) andC_(f) are performed over a frequency range. The parallel compleximpedance (i.e., amplitude and phase) of fluid sensor resistor RTD_(f)in parallel with fluid capacitance C_(f) is evaluated over a frequencyrange. RTD_(f) can be separately evaluated in the real component of thecomplex impedance vector and C_(f) can also be separately evaluated inthe imaginary component of the complex impedance vector.

When the voltage terminal T1 with respect to terminal voltage T2 ispositive, diode D1 is ON and diode D2 is OFF. In this diode ON-OFF biascondition, the measurements across terminals T1 and T2 of compleximpedance of the helm resonator is evaluated over a frequency range ofinterest (e.g. amplitude and phase). Measurements of complex impedancefor Helm Resonators provide sensor data for fluid density, viscosity andsonic speed determination. Shown in FIG. 5 are elements for RTD_(f),C_(f) (C_(f)-A and C_(f)-B capacitor plates) and Helm resonators whichare embedded in the multiple-sensor pressure feedthrough assembly 90 andtheir elements are exposed to the fluid to perform fluid sensingfunctions. Circuit components D1 and D2 are also mounted in themultiple-sensor pressure feedthrough assembly but are not exposed to andnot in contact with the fluid but are protected from the surroundingfluid(s) and respective pressure.

FIG. 10 illustrates another example embodiment of a circuit 220 that canbe used with embodiments of the present disclosure. Instead of diodes,the circuit 220 of FIG. 10 includes a MOSFET 222(metal-oxide-semiconductor field-effect transistor) for switchingbetween measurements modes. Accordingly, FIG. 11 illustrates a waveform240 for operation of the circuit of FIG. 10. Other electrical circuitembodiments can be used to combine these multiple sensor measurementsover a two-wire connection. C_(f) plates exposed to the fluid primarilydetect the fluid capacitance C_(f) whose measurements are dependent onthe fluid relative permittivity (dielectric constant).

The fluid capacitance C_(f) measurement reads higher for higher relativepermittivity fluid (e.g. water with ϵ_(w)=80), and reads lower for lowerrelative permittivity fluids (e.g. oil with ϵ_(oil)=2.2 or air withϵ_(air)=1), providing indications of the type of fluid present in theproduction flow line. Some constant fluid independent parasiticcapacitance associated with capacitor's plate protective thin layer ispresent in series with each capacitor plate of the fluid capacitanceC_(f), which can be accounted for during the complex impedancemeasurement evaluation to extract the C_(f) from the net imaginarycomponent complex impedance measurement. The fluid temperature sensorRTD_(f) is a Resistance Temperature Detector (RTD) or optionally withsilicon-based MEMS chip for example. The RTD may provide fluidmeasurements calibration data and complementary thermal conditions ofthe fluid (e.g. heat capacity evaluation), which affects the density,sonic speed and viscosity piezoelectric helm resonator measurements.

The RTD_(f) measurement can provide additional measurements such asThermal Mass Flow. Thermal. mass flow indicates the mass flow rate ofgases and liquids directly evaluated in a point or sensed area. Massflow measurements are unaffected by changes in viscosity, density,temperature or pressure. In this type of thermal immersion or immersibletype flow meter, the heat is transferred to the boundary layer of thefluid flowing past and over the heated surface (heated directly orindirectly).

In some embodiments, such as in the illustrated embodiment, theelectrode 110 extends an electrode length, which is less than the lengthof the strain bar 98.186. However, it should be appreciated that invarious embodiments the length of the electrode may be substantiallyequal to the length of the strain bar 98. In various embodiments, asurface area of the electrode 110 may determinate, at least in part, amagnitude of an emitted signal. Accordingly, a larger surface area mayinduce more movement of the piezoelectric helm resonator 90, as well asimprove a signal/noise ratio associated with the helm resonator sensor90. The electrode 110 also includes an electrode height, which is lessthan a height of the strain bar 98. However, in various embodiments, theheights of the electrode 110 and the strain bar 98 may be substantiallyequal. It should be appreciated that certain terms such as height,thickness, width, and the like may be used interchangeably to describevarious properties of the piezoelectric helm resonator 92. These termsmay be interchangeable due to the three dimensional coordinate systemand the point of view that the piezoelectric helm resonator 92 isviewed. For instance, a height (substantially up and down relative tothe page) may be viewed as a width (substantially left to right relativeto the page) based on the perspective at which the piezoelectric helmresonator 92 is viewed.

Embodiments of the present disclosure provide an optical sensor 94capable of three phase measurements for downhole logging. Techniques ofthe present disclosure utilize Attenuated Total Internal Reflection(ATIR) spectroscopy for the detection of different fluid phase fraction.The ATIR spectroscopy technique is based on light passing through asensing element that is in contact with the sample under investigationand interacting with it through multiple total internal reflectionswhere each reflection results in an evanescent wave and absorption ofenergy into the sample. The intensity of absorption for each fluid typedepends on the wavelength. The amount of light absorbed by the sample atdifferent wavelengths/frequencies depends on the presence andconcentration of each constituent. Therefore, the absorption spectrum ofthe sample, or the frequency distribution of the absorbed light, can beused to identify the composition of the sample. Currently, commercialproduction logging tools only distinguish liquid from gas but not oilfrom water. The present disclosure aims to distinguish all three phases(oil, water, gas) by using optical absorption spectroscopy along withsample fluorescence and physical property measurements (fluid density,viscosity, and sound speed) made by a co-located helm piezoelectricresonator. By utilizing multiple types of measurements, the redundantinformation provides confirmation of the three-phase analysis.

Transmission absorption spectroscopy requires samples that aresubstantially optically translucent in the range of frequencies beingstudied. Therefore, conventional transmission absorption spectroscopy isdifficult or impossible for analysis of very dark or opaque samples. Invarious embodiments, for opaque liquids and slurries, attenuated totalinternal reflection spectrophotometry (also known as “ATR” or “ATIR”spectrophotometry) is used where internal reflection of the light occursat the interface between two media having different refractive indices.The attenuation of the light beam on reflectance is proportional to thechange in refractive index between the two media at the interface.Because the refractive index tends to change markedly near absorptionbands and becomes complex with an imaginary, absorptive component, theATIR spectrum of a substance is similar to its absorption spectrum. Ingeneral, the ATM spectrum of a sample is independent of the truethickness of the sample, but varies depending on the angle of incidenceof the incident light, which determines the penetration depth of theevanescent wave beyond the sapphire tip into the fluid, whichconstitutes the effective sample thickness or transmission path length,which is typically 50 to 100 microns. The smaller the angle ofincidence, the greater the penetration into the sample fluid. However,the angle of incidence should be greater than the critical angle fortotal internal reflection to occur.

FIG. 12 is a representation 300 of the optical sensor 94 of presentembodiments. Specifically, FIG. 12 illustrates light of multiplewavelengths traveling from an optical source 302, through the opticaltip 304 that is adjacent a sample fluid 308, and to a detector 306, inaccordance with example embodiments of the present disclosure. In someembodiments, 2 or 3 color LED or laser light sources are used whosephotons may be absorbed almost solely by its correspondingtarget-species (e.g., gas, oil, water). Infrared light inducedevanescent-field absorption causes attenuation of light at an absorptionpeak (1450 nm) of water when the fluid is water. In principle, the sameapproach could be used for oil at a wavelength (1740 nm) where oil hasan absorption peak. However, a more convenient approach when the fluidis oil, uses blue light induced evanescent-field penetration into thefluid, which induces fluorescence (primarily from aromatics) andabsorption (primarily from asphaltenes) in the oil. Water and naturalgas do not fluoresce. Both 1450 nm infrared and 405 nm blue light aresubstantially not absorbed by natural gas. In some embodiments, twowavelengths of light can be used as the light source. For example, onesuch wavelength may be 405 nm, which is the wavelength that may inducefluorescence in oil. The other wavelength may be 1450 nm, the wavelengththat is effectively absorbed by water. An optional third light may beused for reference measurement. Light is emitted from the two sourcesdown a single fiber to the bi-conical tip, where the light interactswith the media and is then reflected from the end of the tip andreturned back down the fiber to photodetectors. An optical system, suchas illustrated in FIG. 17, is configured to manage the combination andsplitting of the emitted and returned light for the two wavelengths.

FIG. 13 illustrates a detailed representation 310 of the behavior of theemitted light at the interface 312 of the optical tip 304 and the samplefluid 308, and shows the reflection and attenuation of light through theoptical tip 304, in accordance with example embodiments of the presentdisclosure. Light passing through the optical tip 304 interacts with theadjacent sample fluid 308 through multiple total internal reflections314 where each reflection results in an evanescent wave 316 andabsorption of energy in the sample fluid 308. The intensity ofabsorption for each fluid type depends on the wavelength of the sourcelight.

In some embodiments, the optical sensor is designed such that it cangenerate multiple reflection points 316 along the optical length of theoptical tip 304. For example, the light source 302 may be positionedwith respect to the optical tip 304 at designated incidence angle inorder to produce the multiple reflection points 316. For each of thereflection points 316, an evanescent field 316 is generated whosewavelength is the same as the incident wavelength, as shown in FIG. 13.The loss in intensity due to absorption by the sample fluid is generallyproportional to the number of reflection points. In some embodiments,the design target is to maximize the number of reflections (e.g.,50-100). The intensity of each reflection also depends on the loss ofbeam power due to absorption of the evanescent wave for a singlereflection event. The primary choice for sensing element material fordownhole application is sapphire due to its high refractive index (1.75)compared to the fluid media of interest, its hardness (9 on the Mohsscale) against scratching, and its ability to be machined and polishedinto useful profiles, and its high chemical resistance. Differentsapphire sensing tip designs may be used in different cases, asillustrated in FIG. 16.

FIG. 14 illustrates a side view of the optical tip 304 in accordancewith example embodiments of the present disclosure. The optical tip 304is immersed into the media such as a sample fluid to be detected. Inexample embodiments, the optical tip 304 has a bi-conical shape. In someembodiments, the optical top 304 is a sapphire fiber. FIG. 15 is linedrawing illustrating the profile 330 of such a bi-conical optical tip304. Light emitted from the light source 302 (FIG. 5A) is transmittedinto a single fiber to the bi-conical optical tip, where the lightinteracts with the surrounding media (e.g., sample fluid) and is thenreflected from the end of the optical tip 304 and returned back out ofthe optical tip 304 where it is detected by the photodetectors. Themakeup of the sample can be determined based on the spectral content ofthe returning light detected by the photodetector. Thus, increasing thespectral differences caused by the different media can improve the datasignal. The returned light is registered by a spectral analyzingreceiver such as a spectrally resolved detector that measures therelations between power/intensity of different wavelength, whichcorresponds to different components of the media. The bi-conical designof the optical tip 304 of the present disclosure aims to optimize thesemeasurements. The bi-conical shape facilitates total internal reflectionthroughout the entire optical tip 304 due to the angles, so that themaximum amount of light is returned to the detector, rather than lostout of the optical tip 304. This allows for a more robust signal fromwhich a clearer measurement can be made with respect to the content ofthe sample.

In some embodiments, the optical tip 304 comprises a first conicalportion 322 and a second conical portion 324, the first conical portion322 positioned relatively proximal to the light source 326 and thesecond conical portion 324 forming a distal end of the optical tip 304,wherein the first conical portion 322 has a slope of a first angle and asecond portion 324 has a slope of a second angle steeper than the firstangle. In some embodiments, the optical tip 304 includes a cylindricalor straight portion 328 relatively more proximal to the light source 326than the conical portions 322, 324.

FIG. 16 illustrates a plurality of example configurations of bi-conicaloptical tips 330, in accordance with example embodiments. The opticaltips may have varying slopes and angles for the conical portions.Depending on various design and application factors, differentconfiguration of bi-conical optical tips may optimally facilitate totalinternal refraction and minimize signal loss.

FIG. 17 is a diagram illustrating an optical system 340 for the opticalsensor, in accordance with example embodiments of the presentdisclosure. The optical system 340 includes a first light source 342 foremitting light in the visible light spectrum and a second light source344 for emitting an infrared light. In some embodiments, the combinationof such light sources may be referred to as one light source. In someembodiments, light emitted from both sources travel through respectiveaspheric lens 346, 348. The visible light and the infrared light boththen arrive at a beam combiner 350 and get combined into a single beamof source light. In some embodiments, the single beam of source lightthen travels through a beam splitter 352, where a portion of the sourcelight is redirected to a detector 354 for reference/calibrationpurposes. The remaining portion of the source light travels through thebeam splitter 352 and through a mirror 356 to the optical tip 358wherein it can interact with the sample fluid. Light returning from theoptical tip 358 theoretically includes portions of both the visiblelight and the infrared light. The actual content of the returning lightdepends on the makeup of the sample fluid and corresponding attenuationof the light components. The returning light reaches a dichroic mirror356, where a portion of the visible light is redirected towards avisible light detector 362. In some embodiments, the redirected visiblelight may travel through one or more of a lens 364 or filter 366 beforethe visible light detector 362. The rest of returning light travelsthrough the dichroic mirror 356 and is redirected at the beam splitter352 to a second bicolor detector 368, where measurements on thereturning light are made to determine the makeup of the sample. Theremay be fewer or more lens, filters, and the like, positioned at variouspositions for various effects.

FIG. 18 is a flow chart of an embodiment of a method 130 for collectingand analyzing data utilizing the downhole fluid analysis device 90. Itshould be understood that, for any process described herein, that therecan be additional, alternative, or fewer steps performed in similar oralternative orders, or concurrently, within the scope of the variousembodiments unless otherwise specifically stated. The illustrated method130 includes positioning 132 a fluid sensor in a wellbore, in which thefluid sensor comprising co-located piezoelectric helm resonator, opticalsensor, fluid capacitance, resistance temperature detector, thermal massflow meter and electromagnetic spectroscopy sensor. Co-location isimportant because, for correct interpretation, we want all sensors to bereading the same fluid at the same time.

The method further includes applying 134 electrical energy to thepiezoelectric helm resonator to excite the piezoelectric helm resonator,receiving 136 a first signal from the piezoelectric helm resonator, anddetermining 138 one or more of density, viscosity, or sound speed of aregion of fluid in the wellbore based at least in part the one or moresignals from the piezoelectric helm resonator. Multiple fluid sensortime series measurements are acquired over a period of time and invarious points spatially distributed around the fluid flow pathcross-section inside the tubular. These flow cross-section spatialdistributions recorded over a time interval as time series data arrayscan be used to construct mass and volume three phase flow imaging,providing a visualization of multiple phase fluid flow patterns andcolors indicating fluid characteristics and fluid types flowing insidethe tubular.

These multiple phase fluid flow visualizations can be used for reservoirwells production evaluation and diagnostics, leading to intervention,injection stimulus, and remediation procedures required for performingreservoir and well flow assurance program goals. The method alsoincludes receiving 140 a second signal from the optical sensor,determining 142 one or more optical properties of the region of fluidbased at least in part on the second signal, receiving 144 a thirdsignal from the spectroscopy sensor, and determining 146 one or morespectroscopy characteristics of the region of fluid based at least inpart on the third signal. In some embodiments, various additionalinterpretive steps can be performed back on the detected information.For example, the method may also include evaluating 148 a fluidcharacteristics (e.g., fluid types), and/or imaging 148 b fluid typesand flow in the wellbore or in the tubulars.

In some embodiments, the density, viscosity, sound speed, one or moreoptical properties, and one or more spectroscopy characteristics areassociated with the same fluid domain and time. At least some of theseparameters can be used to further estimate other in situ characteristicsof the well fluid, including for example, live-oil oil holdup, live-oilgas-oil-ratio, live-oil sound speed, live-oil bulk modulus, live-oilmass density, or dead-oil mass density. In order to make thesecorrelations the measurements for sound speed, acoustic impedance andbulk modulus of the composite fluid flow must be obtained in a specificcongruent manner. That is, from a single measurement domain [M-domain]with a sensing field of interaction that is simultaneous and congruentrelative to all the acoustic measurements and all thecontinuous/dispersed particles. The co-located nature of thepiezoelectric helm resonator, the optical sensor, and the spectroscopysensor allows such and other measurements to be made for the same fluiddomain and at the time.

In various embodiments, the change in fundamental resonance frequencyspectra of the piezoelectric helm resonator that is coupled to a fluiddue to changes in the visco-acoustic properties of the local fluidvolume. The design of the helm resonator creates a ‘self-equilibrated’standing acoustic wave pattern between the opposing resonator tines anddevelops a localized Helmholtz resonator without the need for anexternal reactionary cavity wall. This phenomenon allows the sensor tobe utilized in a variety of configurations, including the combination ofan array of sensors distributed throughout the borehole cross section toanalyze multi-phase stratified production flows.

For the production logging applications several design characteristicsderive from the fact that the downhole environment for the applicationinvolves borehole fluid flows of significant ranges of flow speeds, abroad variety of multi-phase fluid properties to be investigated, andextreme downhole pressures and temperatures. The measurement relies onthe resonant excitation of a formed volume of the fluid mixture ofinterest, and the sensing of the changes in resonance frequency spectraof the electrical admittance response of the sensor with changes in thevolume fluid properties. The piezoelectric helm resonator functions bygenerating a “self-equilibrated” acoustic wave pattern in the resonanceformed volume between the two sets of vibratory tines. This phenomenoncreates an intrinsic Helmholtz resonator of the fluid volume between thehelm tines and allows the sensor to be simply deployed in any open-fieldfluid domain. This then also ensures the measurement of the fluid isclosely representative of the local borehole flow across the sensor.

A complex admittance is measured from the piezoelectric helm resonatorover a frequency range, producing frequency dependent curves withcorresponding phase and amplitude frequency response or its real andimaginary complex frequency response components. Quantitative numericalfeatures extracted from the piezoelectric helm resonator's real andimaginary complex admittance amplitude and phase frequency dependentcurves can be used as parameter inputs to various formulas, thresholddetectors, and fluid property discriminators in one, two and three-phasefluid flow. This can be used to produce tubular mass flow and volumetriccross-section image and distribution estimate of fluid density,viscosity and sonic speed, fluid phase detection, fluid type detection,three-phase fluid type change, mixed three-phase fluid detection, mixedtwo-phase fluid detection, variation statistics or detection thresholdsof fluid density, viscosity or sonic speed, increase or decrease offluid's density, viscosity or sonic speed.

The piezoelectric helm resonator's real and imaginary complex admittanceamplitude and phase frequency dependent curves, and any of theirderivative curves with respect to frequency can apply their respectivecalculated quantitative parametric measurements for fluid property anddynamic flow behavior evaluation and mapping with formulas, thresholddetectors and discriminators as discussed above. The calculatedquantitative parametric measurements of these curves can include forexample, but are not limited to, an integral of curve differencescomputed over a frequency range measured at different times or similarlyan integral of difference of separately computed non-overlapping curvewindow moving averages for example for evaluation and determination ofdynamic fluid flow behavior within the tubular. Other calculatedquantitative parametric measurements include frequency at the curve'speak values, frequency difference between curve's peaks, curvedifferential value between positive and negative curve's peak values,frequency interval between curve derivative zero-crossings, parametercomputation using the curve's derivative positive and negative peakvalues or frequencies at peaks (sums or differences for example),maximum curve derivatives with respect to frequency, curve peakfrequency width at 50% of the peak value (or width at other chosen peakpercent values).

The production logging diagnostic, predictive, or analytical method mayuse one or more curve frequency dependent values measured or derivedfrom measured curve values. Such values can be measured in one ormultiple distributed sensors, at one or different points of time, orover different time intervals. Values can be applied as inputs toformulas, threshold detectors, and discriminators evaluated with ameasured or computationally derived curve. Calculated quantitativeparametric measurements of the curves can be used for fluidcharacteristics and properties computation, along with descriptive andanalytical statistics in order to evaluate and analyze productionlogging flow.

FIG. 19 is a block diagram of an embodiment of a machine learning system250 that may be utilized with embodiment of the present disclosure.Embodiments of the present disclosure may utilize machine learningtechniques to associate specific electromagnetic impedance spectroscopywith specific fluid mixtures, thus enabling not only fluid propertyidentification but fluid mixture characterization. The machine learningtechniques may include one or more neural networks (e.g., convolutionalneural networks, fully connected neural networks, recurrent neuralnetworks, etc.) to analyze how data related to electromagnetic impedancespectroscopy may relate to ground truth information related to fluidmixture characterization. In other words, the machine learning methodmay obtain information identifying fluid mixture characterizations basedon electromagnetic impedance spectroscopy (e.g., a ground truth) andthereafter “learn” how different electromagnetic impedance spectroscopyinformation may correlate to that fluid characterization, as well asothers. In certain embodiments, the machine learning techniques mayincorporate one or more open source machine learning libraries, such asTensorFlow, scikit-learn, Theano, Pylearn2, NuPIC, and the like.

It should be appreciated that in certain embodiments the machinelearning system 250 may be incorporated into a control system associatedwith the wireline/drilling system 20. The control system may include oneor more processors and memories. The memories may store instructionsthat, when executed by the processors, perform one or more functions.Additionally, in embodiments, the machine learning system 250 may beassociated with a remote server having a processor (e.g., centralprocessing unit, graphics processing unit, etc.) and a memory. In theillustrated embodiment, the machine learning system 250 includes amachine learning module 252 that may be trained using known information(e.g., a ground truth) such as a database 254. In this training step,the machine learning module 252 is utilized to correlate data betweenfluid mixtures and their associated electromagnetic impedancespectroscopy. It should be appreciated that the machine learning module252 may be trained using any variety of methods, such as backpropagation, clustering, or any other reasonable methods.

As shown in FIG. 19, data (e.g., 266 a, 266 b, 266 c) from the fluidanalysis tool 40 may be transmitted to a network 256, for example via anetwork communication system, such as the Internet or the like. Thenetwork 256 may include the database 254 and/or be in communication withthe database 254, which may be stored in a data store 258 which can be acloud storage architecture accessible by multiple data sources supplyingsensorial data remotely scattered and users' client base via an internetnetwork. The data store 258 may be utilized for training purposes forthe supervised or unsupervised machine learning module 252 or totransmit data to the machine learning module 252 for evaluation. Itshould be appreciated that data may also be transmitted directly to themachine learning module 252 from the network 256.

The illustrated embodiment of the machine learning module 252 includes aconvolutional neural network that takes input 260 through one or moreconvolutional steps 262, which may include pooling, non-linearization(e.g., ReLu), filtering, and the like. The result of the convolutionalsteps 262 may be further processed to from an output 264 based on one ormore parameters of the machine learning module 252. For instance, if themachine learning module 252 is trained to identify fluid mixtureproperties, such as a percentage of drilling mud in the fluid, then themachine learning module 252 may output information indicative ofdifferent percentages of fluids within the fluid cavity, a predefinedcharacterization (e.g., mud-heavy, mud-light, etc.), or a percentage ofmud. In certain embodiments, this may be referred to as identificationof the contamination of the fluid.

The foregoing disclosure and description of the disclosed embodiments isillustrative and explanatory of the embodiments of the invention.Various changes in the details of the illustrated embodiments can bemade within the scope of the appended claims without departing from thetrue spirit of the disclosure. The embodiments of the present disclosureshould only be limited by the following claims and their legalequivalents.

1. A downhole fluid analysis system, comprising: an optical sensorcomprising: a light source configured to emit light comprising aplurality of wavelengths; a light detector; and an optical tip throughwhich at least a portion of the light travels and returns to thedetector, wherein the incident angle of the light causes total internalreflection within the optical tip; a piezoelectric helm resonator,wherein the piezoelectric helm resonator generates a resonance responsein response to an applied current; and an electromagnetic spectroscopysensor positioned symmetrically with respect to the piezoelectric helmresonator in at least one direction.
 2. The system of claim 1, whereinthe light is reflected in the optical tip at one or more reflectionpoints, and wherein each reflection point generates an evanescent wavein a medium surrounding the optical tip.
 3. The system of claim 1,wherein the light is internally reflected in the optical tip at aplurality of reflection points.
 4. The system of claim 1, wherein thelight causes florescence in a medium surrounding the optical tip, theflorescence indicative of the presence of oil in the medium.
 5. Thesystem of claim 1, wherein the light emitted by the light sourceincludes at least a first wavelength and a second wavelength, whereinattenuation of the first wavelength indicates presence of a first fluidtype adjacent the optical tip and attenuation of the second wavelengthindicates presence of a second fluid type adjacent the optical tip. 6.The system of claim 5, wherein the first wavelength is attenuated by thepresence of oil and the second wavelength is attenuated by the presenceof water.
 7. The system of claim 1, wherein the light detector is aspectrally resolved detector and detects intensity of differentwavelength in the received light.
 8. The system of claim 1, wherein theoptical sensor is positioned symmetrically with respect to thepiezoelectric helm resonator.
 9. A downhole fluid analysis device,comprising: an optical sensor comprising: a first light source thatemits light of a first wavelength; a second light source that emitslight of a second wavelength; a beam combiner positioned to combine thelight from the first light source and light from the second light sourceinto a light beam; an optical tip positioned to receive the light beam,wherein an angle of incidence of the light beam creates internalreflection of the light beam within the optical tip; and a lightdetection system positioned to receive returned light from the opticaltip, the light detector resolving wavelengths present the returnedlight, and the intensity of the wavelengths.
 10. The device of claim 9,wherein the first light source emits a visible light and the secondlight source emits an infrared light, and wherein the light beamincludes the visible light and the infrared light.
 11. The device ofclaim 9, wherein the light detection system comprises a visible lightdetector and an infrared light detector.
 12. The device of claim 9,wherein the light detection system comprises a spectrally resolved lightdetector.
 13. The device of claim 9, wherein the light is reflected inthe optical tip at one or more reflection points, and wherein eachreflection point generates an evanescent wave in a medium surroundingthe optical tip.
 14. The device of claim 9, wherein the light beam isinternally reflected in the optical tip at a plurality of reflectionpoints.
 15. The device of claim 9, wherein the light detection systemdetects attenuation of the first wavelength and the second wavelengthsbased on the returned light, wherein attenuation of the first wavelengthindicates presence of a first fluid type adjacent the optical tip andattenuation of the second wavelength indicates presence of a secondfluid type adjacent the optical tip.
 16. The system of claim 15, whereinattenuation of the first wavelength is attenuated by the presence of oiland attenuation of the second wavelength is attenuated by the presenceof water.
 17. A method of obtaining fluid properties in a well,comprising: positioning a fluid sensor in a wellbore, the fluid sensorcomprising co-located piezoelectric helm resonator, optical sensor andelectromagnetic spectroscopy sensor; applying electrical energy to thepiezoelectric helm resonator to excite the piezoelectric helm resonator;receiving a signal from the piezoelectric helm resonator; determiningone or more of density, viscosity, or sound speed of a region of fluidin the wellbore based at least in part the first signal from thepiezoelectric helm resonator; receiving an electromagnetic spectroscopysignal from the spectroscopy sensor emitting a light into an optical tipof the optical sensor; directing the light through a plurality ofinternal reflections in the optical tip before exiting the optical tipas returned light; receiving the returned light from the optical tip ata light detection system; and analyzing the spectral content of thereturned light to determine components of the fluid;
 18. The method ofclaim 17, further comprising: determining a concentration of oil in thefluid based on the intensity of the first wavelength in the returnedlight.
 19. The method of claim 17, further comprising: determining aconcentration of water in the fluid based on the intensity of the secondwavelength in the returned light.
 20. The method of claim 17, whereinthe light is reflected in the optical tip at one or more reflectionpoints, and wherein each reflection point generates an evanescent wavein a medium surrounding the optical tip.